Corrosion and Scale Formation in High-Temperature Sour-Gas Wells
Sour gas is being produced from a number of carbon-steel-completed wells in the US, Canada, France, and Saudi Arabia.
Sour gas is being produced from a number of carbon-steel-completed wells in the US, Canada, France, and Saudi Arabia. The gas stream contains various levels of hydrogen sulfide and carbon dioxide (CO2) and is produced from high-temperature reservoirs with temperatures ranging from 160 to 410°F. The combination of hydrogen sulfide with high temperatures introduces challenges related to corrosion and iron sulfide (FeS) scale formation.
FeS is found naturally in different forms. The gas-production systems studied in this paper have large concentrations of hydrogen sulfide, so iron is a limiting reactant in these systems. FeS formation is favored thermodynamically. In anoxic conditions, the solubility of the ferrous ion is aided by the formation of aqueous iron sulfide complexes. As FeS scales sulfidize, they become increasingly difficult to dissolve with acid.
Source of Iron. Iron can come from reservoir rock, drilling fluids, and corrosion during acidization and production. Many reservoir rocks contain small amounts of iron. Contamination and corrosion during the drilling process also could lead to high iron content in drilling fluids. Acidization has been considered to be a primary source of reprecipitated FeS. FeS scale has been found in well tubulars following acid treatments of deep sour-gas wells.
The corrosion of iron tubulars forms one source for iron scale. General corrosion rates of mild steel in sour systems are less when compared with sweet corrosion. FeS scales are less dense than iron, so sour corrosion is associated often with FeS deposits three to five times thicker than the corroded iron. Corrosion monitoring is important in operating a sour-gas production facility. Corrosion inhibition has been used by different producers to prevent sour corrosion and the associated buildup of FeS scale.
Corrosion Monitoring. It is essential to monitor corrosion and scale formation. This is often assisted by measuring various operational parameters that can give insight into the scaling condition of a gas well. Corrosion coupons are weighed samples of metal representative of the metallurgy of the well or pipe that are introduced into the process and later removed, cleaned of all corrosion products, and weighed. Electrical-resistance probes measure the electrical resistance of a wire made of material similar to the metallurgy of the well or pipe that is placed in a well or pipe. As the wire corrodes, its electrical resistance increases, allowing one to measure the general corrosion of the wire, which should be similar to that of the pipe or well.
Corrosion Inhibition. Batch treatments with corrosion inhibitors were used in Bahrain to protect wells from initial production (with 500 ppm hydrogen sulfide and 6.2% CO2) until 1985. The batches consisted of 950 bbl of diesel with 10% amine inhibitor. The batches were allowed to fall for 24 hours to allow the inhibitor to reach the bottom. A gradiomanometer was used to assess the fall of the liquid in the tubing. The tool indicated that excess inhibitor reached the bottom approximately 4½ hours after injection started. Amine residuals indicated that the frequency for treatment at that time was 6 to 7 months. Batch treatments were effective in preventing corrosion-induced tubing failures during this period.
FeS-Scale Prevention and Removal
In sour environments, FeS scale occurs readily and is difficult to inhibit. Often, the inhibitor concentration is high compared with the limiting-reactant concentration. FeS dispersants have been used to keep FeS in the produced water and avoid its precipitation. Chemical removal with acid releases hydrogen sulfide, and this has prompted the development of mechanical methods for scale removal. There are several FeS-scale dissolvers with high FeS-dissolving power, high pH, and low corrosivity for iron.
Scale Inhibition. A few existing scale inhibitors in laboratory studies have been found to affect FeS precipitation at a concentration of 100 ppm in experiments with 10 ppm Fe2+ and only 50 ppm sulfide at 60°C. The kinetics and inhibition of ferrous sulfide nucleation and precipitation have been studied from 4 to 75°C at different hydrogen-ion concentrations using sodium sulfide and ferrous chloride solutions. It was found in these studies that pH is the most influential factor in iron sulfide formation. Some commercial scale inhibitors required large concentration to show some reduction in formation rates. On the other hand, a relatively small amount of sodium ethylenediaminetetraacetate is able to inhibit FeS nucleation in experiments where FeS formation is studied by contacting equimolar solutions of iron and sulfide solutions.
Scale Dispersants. A polymer prepared by the polymerization of monomers such as 3-methacrylamido-propyl tri-methyl chloride has been used to disperse FeS to prevent its deposition in equipment. The product was used to prevent oil-and-water-separation problems caused by FeS deposition. The product kept the particle size of FeS small, preventing its deposition in the separator, and facilitated the transport of small FeS-scale particles in the produced water.
Scale Removal. Once scale forms, it is essential to remove it so that the productivity of affected wells can be restored. Mechanical and chemical methods have been used to remove FeS scales.
It has been found that a fluidic-oscillation-technology cleaning device and a high-pressure jetting tool with a downhole motor or turbine with mills are effective in removing FeS scales. Current mechanical procedures involve temporary reservoir isolation without formation damage. In a severely scaled well, the differential between the pressure upstream of the choke and that downstream of the choke is not changed even though one has decreased the choke of the well.
Chemical dissolvers have traditionally used strong mineral acids such as concentrated hydrochloric acid. These dissolvers can be corrosive to well tubulars and liners without the use of iron-control agents. Strong mineral acids can cause rapid generation of hydrogen sulfide. Both iron-control agents and hydrogen sulfide scavengers interfere with the dissolving power of hydrochloric acid. FeS-scale dissolvers with high dissolving power, high pH, and low corrosivity for mild steel have been found in some studies.
Sour-Gas-Production Experience Worldwide
FeS-scale formation in water-supply wells and in sour-oil and -gas wells has been investigated. FeS scale was obtained from an oil well with low water cut, and scale samples were also obtained from water-supply wells. Some of the FeS scales from oil wells contained hydrocarbon levels as high as 10%. The removal of FeS scales included both mechanical and chemical cleaning. Squeeze treatments were applied in several water-supply wells that produce water from a sandstone formation.
Scale compositions for five wells from Saudi Arabia were examined. On average, scale samples consisted of 43% FeS and 37% iron (oxyhydr) oxides. The composition of scale was measured at different depths for one well. At most depths, FeS is the predominant scale. One possible explanation of the presence of ferric ions is acid simulation. The composition of the scale is often layered, with the flow side having higher amounts of FeS than the tubing side. Higher amounts of FeS on the tubing side may result from sulfidization of the initial iron scale by hydrogen sulfide.
Iron in the scales has a limited number of sources. A study was performed to determine the amount of iron in reservoir rock by dissolving rock in a specified amount of acid and determining the amount of iron by inductively coupled atomic emission spectroscopy. Soluble-iron content in drilling fluids can be as high as 1200 mg/L or below 250 mg/L. High iron concentrations (80 000 mg/L) can be obtained during the flowback of a pickling treatment. Large amounts of iron can flow back after an acidizing job.
- Analysis reveals that considerable iron can be released by dissolution of rock with fairly small amounts of iron, drilling-fluid loss, corrosion of well tubing during acidizing, and sour corrosion.
- The large amount of acid introduced during acidizing implies that significant amounts of iron are generated from the formation even if the reservoir rock has as little as 1 mg/g of total iron.
- Acidizing can release large amounts of iron from the well tubing even if the corrosion in the tubing and liner is as low as 0.03 lbm/ft2.
- Stimulation jobs should be planned with fluids that have a high dissolving power yet cause as little corrosion as possible.
- Stimulation methods other than the use of acid should be explored in sour carbonate systems.
- Sour corrosion occurs continuously during well production. The corrosion rates may be low compared with the larger rates seen in sweet corrosion. The low rates, though, can introduce iron into the system continuously to cause iron-scale formation.
- Alternative metallurgy should be explored for liner design.
- Corrosion inhibition should be explored and used to prevent sour corrosion during well production.
- A better understanding of downhole scaling tendency can be obtained by sampling the downhole fluids.
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 173713, “Corrosion and Scale Formation in High-Temperature Sour-Gas Wells: Chemistry and Field Practice,” by Sunder Ramachandran, SPE, Aramco Service Company, and Ghaithan Al-Muntasheri, SPE, Jairo Leal, SPE, and Qiwei Wang, SPE, Saudi Aramco, prepared for the 2015 SPE International Symposium on Oilfield Chemistry, The Woodlands, Texas, USA, 13–15 April. The paper has not been peer reviewed.